1. Field of the Invention
The present invention relates to techniques for remediating hydrate formations in subsea environments. More particularly, the present invention relates to the removal of hydrates from a subsea flowline. More particularly, the present invention relates to gas lift techniques for the disassociation of hydrate formations in subsea flowlines and for the transport of the fluids and disassociated hydrates from the flowline to a surface location.
2. Description of Related Art Including Information Disclosed Under 37 CFR 1.97 and 37 CFR 1.98
More than two-thirds of the earth is covered by oceans. As the petrochemical industry continues its search for hydrocarbons, it is finding that more and more of the untapped hydrocarbon reservoirs are located beneath the oceans. Such reservoirs are referred to as “offshore” or “subsea” reservoirs. A typical system used to produce hydrocarbons from offshore reservoirs uses hydrocarbon-producing wells located on the ocean floor. The producing wells are referred to as “producers” or “subsea production wells”. The produced hydrocarbons are transported to a host production facility. The production facility is located on the surface of the ocean or immediately onshore.
The producing wells are in fluid communication with the host production facility via a system of pipes that transport the hydrocarbons from the subsea wells on the ocean floor to the host production facility. This system of pipes typically comprises a collection of jumpers, flowlines and risers. Jumpers are typically referred to in the industry as the portion of pipes that lie on the floor of the body of water. They connect the individual wellheads to a central manifold. The flowline also lies on the marine floor and transports production fluids from the manifold to the riser. The riser refers to the portion of the production line that extends from the seabed, through the water column, into the host production facility. In many instances, the top of the riser is supported by a floating buoy, which then connects to a flexible hose for delivering production fluids from the riser to the production facility.
The drilling and maintenance of remote offshore wells is expensive. In an effort to reduce drilling and maintenance expenses, remote offshore wells are oftentimes drilled in clusters. A grouping of wells and the clustered subsea arrangement is sometimes referred to as a “subsea well-site”. A subsea well-site typically includes producing wells completed for production at one or more “pay zones”. In addition, a well-site will include one or more injection wells to aid in maintaining in-situ pressure for water drive and gas expansion drive reservoirs.
The grouping of remote subsea wells facilitates the gathering of production fluids into a local production manifold. Fluids from the clustered wells are delivered to the manifold through the jumpers. From the manifold, production fluids may be delivered together to the host production facility through the flowline and the riser. For well-sites that are in deeper waters, the gathering facility is typically a floating production storage and offloading vessel.
One challenge facing offshore production operations is flow assurance. During production, the produced fluids will typically comprise a mixture of crude oil, water, hydrocarbon gases (such as methane), and other gases such as hydrogen sulfide and carbon dioxide. Of equal concern, changes in temperature, pressure and/or chemical composition along the pipes may cause the deposition of other materials, such as methane hydrates, waxes or scales on the internal surface of the flowlines and risers. These deposits need to be periodically removed since buildup of these materials can reduce line size and constrict flow.
Hydrates are crystals formed by water in contact with natural gases and associated liquids. Hydrates can form from hydrocarbons and water at the right temperature and pressure, such as in wells, flowlines, or valves. The hydrocarbons become encaged in ice-like solids which do not flow, but which rapidly grow and agglomerate to sizes that can block flowlines. Hydrates formation most typically occurs in subsea production lines which are at relatively low temperatures and elevated pressures.
The low temperatures and high pressures of a deep water environment cause hydrate formation as a function of the gas-to-water composition. In a subsea pipeline, hydrate masses usually form at the hydrocarbon-water interface, and accumulate as flow pushes them downstream. The resulting porous hydrate plugs have the unusual ability to transmit some degree of gas pressure, while acting as a flow hindrance to liquid. Both gas and liquid may sometimes be transmitted through the plug; however, lower viscosity and surface tension favors the flow of gas.
There are basically four ways known to remediate such hydrate plugs. First, the pressure of the hydrate plug to be changed to a lower pressure, outside the stable range for the hydrates, thereby melting the hydrate. In many instances, it may be difficult to lower the pressure below the hydrate stability pressure. In any event, when the pressure is lowered below the hydrate stability pressure, the decomposition of the hydrate is relatively slow, thereby requiring downtime in the production system for a substantial period of time to remove the hydrate.
Secondly, the temperature of the hydrate can be increased above the hydrate stability temperature. As with the pressure technique described above, raising the temperature of the plug creates the potential for equipment damage and/or personnel safety concerns.
Thirdly, the hydrates can be removed mechanically. While commonly used to remediate hydrate plugs in production wells, this method can be difficult to employ in production equipment and/or pipelines.
Fourthly, it is possible in, and some instances, to inject a chemical, such as alcohol or glycol to dissolve the hydrate. These liquids are effective in melting hydrates and are typically required in relatively large quantities if the plug is extensive. If the plug is a significant distance from the nearest injection location, this method may not be feasible.
In the past, various patents have issued relating to such hydrate remediation activities. For example, U.S. Pat. No. 7,234,523, issued on Jun. 27, 2007 to B. J. Reid, describes a hydraulic friction fluid heater. This method includes pumping a fluid through a length of tubing such that the temperature of the fluid increases. The temperature increase of the fluid is created by friction in the tubing. It can also be created by at least one pressure reducing device, such as an orifice, a pressure reducing valve, or relief valve. A subsea structure may be heated by transferring heat from fluid circulating in a closed loop configuration or by direct application of fluid to the subsea structure by using a nozzle. A remotely-operated vehicle may be utilized to transport some or all of the equipment necessary and to provide power to the pumps used for circulating fluid through the tubing.
U.S. Pat. No. 6,939,082, issued on Sep. 6, 2005 to B. F. Baugh, provides a subsea pipeline blockage remediation method. This method involves the use of a remotely-operated vehicle on the ocean floor to land on and move along a subsea pipeline located above the seafloor. Electrically heated seawater is repeatedly circulated across the outer surface of the pipeline to melt hydrates which have formed on the inside of the pipeline.
U.S. Pat. No. 6,415,868, issued on Jul. 9, 2002 to Janoff et al., teaches a method and apparatus for preventing the formation of alkane hydrates in subsea equipment. This apparatus has at least one flow path through which a well fluid is permitted to flow. The well fluid has a flow temperature and a lower hydrate formation temperature at which hydrates will form in the well fluid. A temperature control device is provided which comprises a housing positioned in heat exchange relationship with respect to the flow path and a phase change material disposed in the housing. The phase change material has a melting point which is below the flow temperature but above the hydrate formation temperature. When the temperature of the phase change material drops to its melting point, the phase change material will solidify and its latent heat will be transferred to the well fluid to maintain the temperature of the well fluid in the flow path above its hydrate formation temperature.
U.S. Pat. No. 5,803,161, issued on Sep. 8, 1998 to Wahle et al., provides a heat pipe heat exchanger for cooling or heating high temperature/high-pressure subsea well streams. This heat exchanger has an annular reservoir surrounding a section of pipeline adjacent the wellhead. One or more heat pipes extend from the annular reservoir into the seawater. In a heat removal configuration, a working fluid is contained within the annular reservoir. The working fluid boils and is evaporated by heat from the wellstream fluid and forms a vapor which rises upwardly into and is condensed within the heat pipes so as to release heat into the surrounding seawater. The recondensed working fluid flows back down into the reservoir to repeat the cycle. In a heat-providing configuration, the working fluid is contained in the heat pipes so as to be boiled by heat transferred from the surrounding seawater. The resulting vapor rises upwardly into the annular reservoir and the heat is transferred to the cooler wellstream fluids.
U.S. Pat. No. 6,776,227, issued on Aug. 17, 2004 to Beida et al., discloses a wellhead heating apparatus and method which serves to prevent freeze-off of wellhead equipment. Radiant heat from a flameless heater is utilized to heat fluid in a heat exchanger, such as a tank or finned radiator. A pump is used to circulate the heated fluid through a conduit loop deployed in thermal contact with the equipment to be heated, such that the heat from the fluid is transferred to the equipment. The equipment is maintained at sufficient temperature to prevent freeze-off.
U.S. Pat. No. 6,260,615, issued on Jul. 17, 2001 to Dalrymple et al., shows a method and apparatus for de-icing oilwells. A power cable is used for heating well bores in cold climates. An electrical switch is located within a wellbore at a selected location in the power cable. The electrical switch is provided to selectively short out the conductors within the power cable so as to allow the power cable above the switch to be used as a resistive heating element to thaw the wellbore.
U.S. Pat. No. 7,036,596, issued on May 2, 2006 B. J. Reid, provides a hydraulic friction fluid heater and method. The method includes pumping a fluid through a length of tubing such that the temperature of the fluid increases. The temperature increase of the fluid is created by friction in the tubing. A subsea structure may be heated by transferring heat from fluid circulating in a closed loop configuration or by direct application of fluid to the subsea structure using a nozzle. A remotely operated vehicle may be utilized to transport the equipment necessary.
U.S. Pat. No. 7,669,659, issued on Mar. 2, 2010 to the present Applicant, teaches a system for preventing hydrate formation in chemical injection piping for subsea hydrocarbon production. This system has a manifold, a production piping communicating with the manifold, a chemical injection line positioned in heat exchange relationship along the production piping, and a fluid delivery system connected to the chemical injection line for passing a heated fluid through at least a portion of the chemical injection line. The chemical injection line has a first portion affixed to a surface of the production piping and a second portion extending outwardly therefrom. The fluid delivery system is in communication with the second portion of the chemical injection line. The chemical injection line extends in a U-shaped pattern or in a spiral pattern around an outer surface of the production piping.
U.S. Pat. No. 8,430,169, issued on Apr. 30, 2013 to Stoisits et al., shows a method for managing hydrates in a subsea production line. The production system includes a host production facility, a control umbilical, at least one subsea production well, and a single production line. The method generally comprises producing hydrocarbon fluids from the production well and through the production line, and then shutting in the production line. The method includes the steps of depressurizing the production line to substantially reduce a solution gas concentration in the produced hydrocarbon fluids, and then re-pressurizing the production line to urge any remaining gas in the free gas phase within the production line back in the solution. The method also includes displacing production fluids within the production line by moving displacement fluids from a service line within the umbilical line and into the production line.
U.S. Pat. No. 8,003,573, issued on Aug. 23, 2011 to Ballard et al., provides a method for remediating flow-restricting hydrate deposits in production systems. In this method, a non-hydrate-forming gas is used to form hydrates at a higher pressure than the existing hydrate through a flow-restricting hydrate.
U.S. Pat. No. 8,424,608, issued on Apr. 23, 2013 to the present Applicant, describes a system and method for remediating hydrates which has a heat storage box with an interior volume, a heater for heating fluid flowing into the hot fluid inlet of the heat storage box, a heat exchanger positioned in the interior volume of the heat storage box so as to be in heat-exchange relationship with heated water from the interior volume of the heat storage box, and a line connected to a heated water outlet of the heat exchanger so as to be manipulated toward a location of the hydrates for the purpose of delivering the heated water toward the hydrates. The heat exchanger is piping extending in a serpentine pattern within an upper portion of the heat storage box.
U.S. Patent Application Publication No. 2010/0047022, published on Feb. 25, 2010 to Y. LeMoign, shows subsea flowline plug remediation. This describes a technique that enables removal of a hydrate plug from a deep water flowline. When the existence of a plug in the flowline is determined, a temporary flowline loop is created to enable repair remedial procedures. The temporary loop is created by deploying a spoolable compliant guide and connecting the spoolable compliant guide to the deepwater flowline. The connection is made in a manner that enables access to both sides of the unwanted plug.
It is an object of the present invention to provide a process for preventing hydrate formation in subsea locations.
It is another object of the present invention to provide a process for remediating hydrate formations that utilizes pressure differentials to disassociate the hydrate formation.
It is another object of the present invention provide a process for remediating hydrates that allows a flow of production fluids to be captured at a surface location.
It is another object of the present invention to provide a process for remediating hydrate formations which is easy-to-use and minimizes time and effort.
These and other objects and advantages of the present invention will become apparent from a reading of the attached specification and appended claims.